In wells that produce both natural gas and oil, the gas and oil exit the formation and enter the perforated casing and tubing string that is located inside of the casing. The gas may flow up the casing or the tubing string, while oil and other liquids travel through the tubing string to the wellhead at the surface. The oil and other liquid are forced to the surface by way of either natural formation pressure or by artificial lifting mechanisms, such as pumps.
For wells whose primary purpose is to produce gas, the presence of liquid at the bottom of the well bore adds backpressure to the formation, and thus inhibits the free flow of natural gas through the well bore to the surface. It has been estimated that 80% of the natural gas wells in the United States suffer from liquids (oil and/or condensates) in the well bore. This produces a condition known as liquid loading, wherein the ability of the well to produce a maximum amount of gas is restricted.
In order to restore production of a gas well to a satisfactory level, it is desirable to remove much of the liquid from the bottom of the well bore. The amount of liquid produced in many wells is insufficient to warrant a pump. Plunger lift systems are used instead. Additionally, plunger lift systems can function to produce oil through the tubing of an oil well in the same manner.
In a plunger lift system, a plunger cycles in the tubing between the top and the bottom of the well bore. As the plunger rises from the bottom of the well bore, it lifts the liquid above the plunger to the surface. Gas pressure below the plunger serves to lift the plunger and the liquid. The gas used to lift the plunger can be either gas produced by the formation or gas injected into the well from the surface. The plunger falls to the bottom by gravity, when the well is shut-in, and gas no longer flows. The plunger is cycled periodically to lift the liquid. Gas is typically produced through the tubing instead of the casing in a plunger lift system.
Because plunger lift systems are used to increase well production, there is a desire to optimize the operation of the plunger. The plunger is typically held at the surface by the either a mechanical latch or by the force of flowing gas in the tubing. A controller or operator determines when enough fluid has entered the bottom of the well bore and appropriate conditions exist, or will soon exist, that will allow the plunger to operate effectively. The well is then closed and the plunger free falls to the bottom of the well. The well is then opened so that the plunger will return to the surface.
Knowing when the plunger hits the bottom of the well is desirable. If the well is opened before the plunger has reached the bottom of the liquid column, the plunger will rise to the surface without a full load of liquid. Not only is this inefficient, but the plunger's rise speed may be too fast, damaging both itself and equipment at the top of the wellhead. The well can remain closed, or shut-in, for a long time to ensure that the plunger has reached the bottom. However, a shut-in well loses production.
Current practice uses estimates of plunger fall speeds and times. For example, estimates of fall speeds range from 250 feet per minute (fpm) to over 1500 μm, depending on the type of plunger. However, some published estimates have been proven to be significantly inaccurate when measured with acoustic test equipment, such as that manufactured by Echometer. It is recognized that the velocity of a plunger significantly decreases when the plunger enters gaseous liquid conditions. While estimated fall velocities in natural gas and gaseous liquid conditions can be approximated through empirical testing, it is necessary to know the height of the liquid column in the well.
Current practice allows the pressure exerted by the liquid column, and thus the height of the liquid column, to be determined measuring the tubing pressure and casing pressure shortly after the well is shut-in at the surface and then comparing the two pressures. However, the liquid gradient (psi/ft) must be known in order to determine the height of the liquid in the tubing and thus to accurately predict the time for the plunger to reach the bottom of the well. Because the liquid gradient depends on the gas content of the liquid, determining the liquid gradient absent direct measurement is difficult.
It also desired to know the position of the plunger in the tubing at all times. This information could be used by an operator to know in real time when the plunger will reach the bottom or top of the well. Knowing the plunger location could greatly assist operators in troubleshooting problems in a well, such as the location of a stuck plunger, in knowing the velocity of the plunger for cycle optimization, in ensuring that the plunger actually reached the bottom of the well before the well is opened, and even to schedule preventive maintenance.
Downhole instrumentation, which would sense parameters relating to the liquid level and fluid gradient, is one answer. But, obtaining data from the downhole instrumentation, and providing power thereto, is costly, time consuming and difficult. Transmitting the data over wires is not practical, as the wires inside of the tubing would interfere with the operation of the plunger. Also, prior art acoustical systems are used to determine well bore conditions, including plunger location. U.S. Pat. No. 6,634,426 is a passive system that uses a microphone at the surface to listen to the plunger rise and fall. The plunger makes acoustical signatures as it passes by collars or joints in the tubing string and when it contacts the liquid. U.S. Pat. No. 4,318,674 uses an acoustical source on the surface to determine the location of the top level of the liquid.
It is desired to improve on the prior art.